A variety of designs exist for the production of hydrocarbons in deep to ultra-deep waters, i.e. depths greater than 4,000 feet. Generally, the preexisting designs fall within one of two types, namely, wet tree or dry tree systems. These systems are primarily distinguished by the location of pressure and reservoir fluid flow control devices. A wet tree system is characterized by locating the trees atop a wellhead on the seafloor whereas a dry tree system locates the trees on the platform in a dry location. These control devices are used to shut in a producing well as part of a routine operation or, in the event of an abnormal circumstance, as part of an emergency procedure.
In wet tree systems, these control devices are located proximate to a subsea wellhead and are therefore submerged. The primary function of the tree is to shut-in the well, in either an emergency or routine operation, in preparation for workover or other major operations.
Dry tree systems, in contrast, place the control devices on a floating platform out of the water, and are therefore relatively dry in nature. Having the production tree constructed as a dry system allows operational and emergency work to be performed with minimal, if any, ROV assistance and with reduced costs and lead-time. The ability to have direct access to a subsea well from a dry tree is highly economically advantageous. The elimination of the need for a separate support vessel for maintenance operations and the potential for increased well productivity through the frequent performance of such operations are beneficial to well operators. Furthermore, the elimination of a dedicated workover riser and the associated deployment costs will also result in a substantial savings to the operator.
Historically, dry tree systems have been installed in conjunction with tension leg platforms or spar-type platforms that float on the surface over the wellhead and have minimal heave motion impact upon the risers. Generically, a riser extending from a tension leg or spar platform is referred to as a top tensioned riser (TTR) as it is either supported directly by the host platform or hull support, or independently by air cans that supply tension to the upper portion. In the case of hull supported TTRs, top tension is supplied via a system of tensioning devices, wherein sufficient tension is applied such that the top tensioned risers remain in tension for all loading conditions. The relative motion between TTRs and the platform in a hull support arrangement is typically accommodated through a stroke biasing action of the tension devices themselves. Therefore, on a spar or tension leg platform, relative movements of the floating platform will be transmitted only minimally through the riser systems because equipment aboard the platform will give and take to accommodate those movements. Particularly, with TTRs, the tension is applied at the top and the tension decreases in a substantially linear profile with depth to the subsea wellhead.
In contrast, vertical riser loads for air can supported TTRs are not carried by the hull of a platform. Instead, the air can supported TTRs ascend from subsea wellheads through an aperture in the work deck known as a moonpool. The TTRs extend through the moonpool and connect to dry trees located on the tops of aircans in the bay area of the platform. Using this construction, each air can supported TTR is permitted to move vertically relative to the hull of the platform through the moonpool. This vertical movement of the TTR relative to the platform is a function of the magnitude of platform offset and set-down, first-order vessel motions, air can area and friction forces between the hull structure and the air cans. The fluid path between the dry tree on the aircan and the processing facility on the vessel is usually accomplished by means of a non-bonded flexible jumper.
Regardless of particular configuration, the tension within a TTR system creates a characteristic shape that is substantially linear and in a near vertical configuration. Since TTR curvatures and capabilities for compliance are relatively small, multiple subsea wells connected to a single tension leg or spar platform by TTR's are required to be closely spaced to one another on the ocean floor. Typically, the maximum distance between the most remote subsea wells in a cluster to be serviced by a single platform via TTRs is 300 feet. Therefore, dry tree platforms, as deployed with currently available technology, require relatively closely spaced subsea wells in order to be feasible. Unfortunately, the placement of subsea wellheads within 300 feet of each other is not always feasible or economically desirable. Changes in locations and types of undersea geological formations often dictate that wellheads be spaced apart at distances greatly exceeding 300 feet. In these instances, it is often less economically feasible to employ dry tree strategies to service these wells as their spacing would require the installation of several tension leg or spar platforms. In these circumstances, wet tree schemes have typically been used.
A dry tree platform system capable of servicing clusters of subsea wellheads at greater spacing distances would offer practical, economic and other advantages. Furthermore, alternatives to tension leg and spar platforms would also be desirable to those in the field of offshore well servicing. Tension leg and spar platforms are relatively expensive endeavors, particularly because of the amount of anchoring and mooring required to maintain them in a relatively static position in rough waters. A platform system having a dry tree arrangement and utilizing a less restrictive and less costly mooring system would be well received by the industry.
The embodiments are detailed below with reference to the listed Figures.